Crude oil development and production from oil bearing formations can include up to three phases: primary, secondary and tertiary (or enhanced) recovery. During primary recovery, the natural energy present in the formation (e.g., water, gas) and/or gravity drives oil into the production wellbore. As oil is produced from an oil bearing formation, pressures and/or temperatures within the formation may decline. Artificial lift techniques (such as pumps) may be used to bring the oil to the surface. Only about 10 percent of a reservoir's original oil in place (OOIP) is typically produced during primary recovery. Secondary recovery techniques are employed to extend the field's productive life and generally include injecting a displacing fluid such as water (waterflooding) to displace oil and drive it to a production wellbore. Secondary recovery techniques typically result in the recovery of an additional 20 to 40 percent of a reservoir's OOIP. However, even if waterflooding were continued indefinitely, typically more than half of the OOIP would remain unrecovered due to a number of factors including, but not limited to, poor mixing efficiency between water and oil due to high interfacial tension between the water and oil, capillary forces in the formation, the temperature of the formation, the salinity of the water in the formation, the composition of the oil in the formation, and poor sweep of the injected water through the formation. Primary and secondary techniques therefore leave a significant amount of oil remaining in the reservoir.
With much of the easy-to-produce oil already recovered from oil fields, producers have employed tertiary, or enhanced oil recovery (EOR), techniques that offer potential for recovering 30 to 60 percent, or more, of a reservoir's OOIP. Three major categories of EOR have been found to be commercially successful. Thermal recovery EOR techniques involve the introduction of heat such as the injection of steam to lower the viscosity of the crude oil to improve its ability to flow through the reservoir. Gas injection EOR techniques use gases, such as nitrogen or carbon dioxide, that expand in a reservoir to push additional oil to a production wellbore, or other gases that dissolve in the oil to lower its viscosity and improve flowability of the oil. Chemical EOR techniques involve the injection of chemicals such as surfactants (surfactant flooding) to help lower the interfacial tension that prevents or inhibits oil droplets from moving through a reservoir, and polymers to allow the oil present in the formation to be more easily mobilized through the formation.
Chemical EOR techniques may be carried out prior to, during or after the implementation of primary and/or secondary recovery techniques. Chemical EOR techniques may also be carried out in conjunction with other EOR techniques that do not involve chemical injection. There are two main types of surfactant flooding techniques. Surfactant Polymer (SP) flooding involves injecting into a reservoir a fluid containing water and/or brine and about 1% by weight surfactant and about 0.1% by weight polymer. Alkali Surfactant Polymer (ASP) flooding involves the injection of water and/or brine containing alkali in addition to surfactant and polymer. ASP systems typically contain on the order of about 0.5-1 wt. % alkali, 0.1-1 wt. % surfactant and 0.1-1 wt. % polymer. Typically, an SP or ASP flood is followed up with an injection of a displacing fluid, e.g., a waterflood and/or polymer “push” fluid. The choice between SP or ASP depends on a number of factors, including the acid value of the oil to be recovered, the concentration of divalent ions (Ca2+, Mg2+) in the brine present in the reservoir, the economics of the project and the ability to carry out water softening or desalination. The surfactant component reduces interfacial tension between water and oil, while the polymer acts as a viscosity modifier and helps to mobilize the oil. Alkali sequesters divalent ions in the formation brine and thereby reduces the adsorption of the surfactant during displacement through the formation. Alkali also generates an anionic surfactant, sodium naphthenate soap, in situ in the formation by reacting with naphthenic acids that are naturally present in the crude oil. The use of relatively inexpensive alkali reduces the amount of surfactant required, and therefore the overall cost of the system. Alkali may also help alter formation wettability to a more water-wet state to improve the imbibition rate.
Introduction of surfactants into a reservoir, sometimes combined with altering the concentration of electrolytes therein, with the goal of displacing the sorbed oil by effecting spontaneous imbibition of water onto the reservoir rock, is an EOR technique known as “wettability alteration.” This technique does not necessarily require low interfacial tensions between the oil and aqueous phases or the formation of a microemulsion phase. It also does not necessarily require a good sweep efficiency of the displacing fluid, and as such could have utility in carbonate reservoirs which can be fractured and typically have poor conformance. Surfactants used in SP and ASP floods have also displayed utility in wettability alteration based EOR techniques.
A surfactant EOR system, after injection into an oil bearing formation, takes up crude oil and brine from the formation to form a multiphase microemulsion in situ which when complete is immiscible with the reservoir crude and exhibits low interfacial tension (IFT) with the crude oil and brine. Commercial surfactant EOR processes are based on achieving ultra-low IFT (i.e., less than 10−2 mN/m) to mobilize disconnected crude oil droplets in the formation and create an oil bank where both oil and water flow as continuous phases. IFT changes with variables such as salinity, surfactant composition, crude oil composition and formation temperature. For anionic surfactants, an optimal salinity exists where microemulsions form which solubilize equal volumes of oil and water, and which exhibit nearly equal IFT's with oil and brine. The ultra-low IFT generally exists only in a narrow salinity range which overlaps the optimal salinity for a given microemulsion.
Internal olefin sulfonates (IOS) are anionic surfactants that have been evaluated as EOR surfactants. Internal olefin sulfonates may be prepared by sulfonation of internal olefins with the aid of SO3 and inert gases and subsequent neutralization. Internal olefins may be subdivided as:
“di-substituted”: R—CH═CH—R;
“tri-substituted”: R2C═CH—R;
and
“tetra-substituted”: R2C═CR2; where R is straight or branched-chain hydrocarbyl.
Internal olefin sources can be obtained from a variety of processes, including olefin (e.g. ethylene, propylene and butylene) oligomerization processes, alpha-olefin metathesis processes, Fischer-Tropsch processes, catalytic dehydrogenation of long chain paraffin hydrocarbons, thermal cracking of hydrocarbon waxes and dimerized vinyl olefin processes. One well known ethylene oligomerization process is the Shell Higher Olefin Process (SHOP). This process combines ethylene oligomerization to form alpha-olefins, isomerization of the alpha-olefins to form internal olefins and the metathesis of these internal olefins with butenes or ethylene to form alpha-olefins of different chain lengths. A problem associated with SHOP mentioned in U.S. Pat. No. 6,777,584 is undesirable branching on the alpha-olefins and internal olefins that often result from the oligomerization/isomerization/metathesis processes. Commercially available internal olefins typically contain on the order of about six mole percent or higher of tri-substituted internal olefins. Moreover, these commercial products typically contain appreciable amounts of non-linear, alkyl branched products. These alpha-olefins and internal olefins have been reported to contain alkyl branching on the order of about six mole percent or higher. Moreover, significant amounts of unreactive, terminally unsaturated vinylidenes of the structure R2C═CH2 (where R is defined as above) are also known to be present in these commercially available materials.
U.S. Pat. Nos. 4,532,053, 4,549,607, 4,555,351, 4,556,108, 4,597,879, 4,733,728 and 4,765,408, disclose micellar slugs containing among other things an internal olefin sulfonate for use in the recovery of oil.